Eccentric sleeve for directional drilling systems

ABSTRACT

A drill bit includes a bit body configured to rotate about a bit rotational axis and a sleeve coupled to the bit body. The sleeve is coupled to the bit body on an uphole portion of the bit body. The sleeve has a smaller diameter than the bit body and is aligned at the edge of the circumference of the bit body.

FIELD OF THE DISCLOSURE

The present disclosure is related to downhole drilling tools including, but not limited to, drill bits, sleeves, bottom-hole assemblies, and more particularly to design, manufacture and/or selection of such downhole drilling tools.

BACKGROUND OF THE DISCLOSURE

Various types of rotary drill bits, reamers, stabilizers and other downhole drilling tools may be used to form a borehole in the earth. Such wellbores are often formed using a rotary drill bit attached to the end of a generally hollow, tubular drill string extending from a well head. Rotation of a rotary drill bit progressively cuts away adjacent portions of a downhole formation using cutting elements and cutting structures disposed on exterior portions of the rotary drill bit. Examples of such rotary drill bits include, but are not limited to, fixed cutter drill bits, drag bits, PDC drill bits, matrix drill bits, roller cone drill bits, rotary cone drill bits and rock bits used in drilling oil and gas wells. Cutting action associated with such drill bits generally uses weight on bit (WOB) and rotation of associated cutting elements into adjacent portions of a downhole formation to push the bit into the formation to cause cutting and drilling. Drilling fluid may also be provided to perform several functions including washing away formation materials and other downhole debris from the bottom of a wellbore, cleaning associated cutting elements and cutting structures and carrying formation cuttings and other downhole debris upward to an associated well surface.

Some rotary drill bits have been formed with blades extending from a bit body with a respective gage sleeve disposed proximate an uphole edge of each blade. Gage sleeves have been disposed at a positive angle or positive taper relative to a rotational axis of an associated rotary drill bit. Gage sleeves have also been disposed at a negative angle or negative taper relative to a rotational axis of an associated rotary drill bit. Such gage sleeves may sometimes be referred to as having either a positive “axial” taper or a negative “axial” taper. The rotational axis of a rotary drill bit will generally be disposed on and aligned with a longitudinal axis extending through straight portions of a wellbore formed by the associated rotary drill bit. Therefore, the axial taper of associated gage sleeves may also be described as a “longitudinal” taper.

SUMMARY

In one embodiment, a drill bit includes a bit body configured to rotate about a bit rotational axis and a sleeve coupled to the bit body. The sleeve is coupled to the bit body on an uphole portion of the bit body. The sleeve has a smaller diameter than the bit body and has a portion aligned with an edge portion of the bit body. The edge portion is located on the circumference of the bit body.

In another embodiment, a downhole drilling tool operable to form a wellbore includes a bit body coupled to an eccentric sleeve. The sleeve is coupled to the bit body at an uphole portion of the bit body. The bit body is configured to remove material to form a portion of the wellbore.

In yet another embodiment, a downhole drilling tool includes a bit body configured to rotate about a bit rotational axis and a first sleeve coupled to the bit body at an uphole portion of the bit body. The first sleeve has a smaller diameter than the bit body and has a portion aligned with an edge portion of the bit body. The edge portion is located on the circumference of the bit body.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete and thorough understanding of the various embodiments and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying drawings, wherein:

FIG. 1A is an illustration of an example directional drilling system for drilling a wellbore;

FIG. 1B is an illustration of an example system operable to simulate drilling a directional wellbore;

FIG. 1C is a block diagram representing various capabilities of systems and computer programs for simulating drilling a directional wellbore;

FIG. 2A is a schematic drawing showing an isometric view with portions broken away of a rotary drill bit with six (6) degrees of freedom which may be used to describe motion of the rotary drill bit in three dimensions in a bit coordinate system;

FIG. 2B is a schematic drawing showing forces applied to a rotary drill bit while forming a substantially vertical wellbore;

FIG. 3A is a schematic representation showing a side force applied to a rotary drill bit at an instant in time in a two dimensional Cartesian bit coordinate system;

FIG. 3B is a schematic representation showing a trajectory of a directional wellbore and a rotary drill bit disposed in a tilt plane at an instant of time in a three dimensional Cartesian hole coordinate system;

FIG. 3C is a schematic representation showing the rotary drill bit in FIG. 3B at the same instant of time in a two dimensional Cartesian hole coordinate system;

FIG. 4A is a schematic drawing in section and in elevation with portions broken away showing one example of a point-the-bit directional drilling system and associated rotary drill bit disposed adjacent to the end of a wellbore;

FIG. 4B is a graphical representation showing portions of a point-the-bit directional drilling system forming a directional wellbore;

FIG. 4C is a schematic drawing in section with portions broken away showing a point-the-bit directional drilling system and associated drill bit disposed in a generally horizontal wellbore;

FIG. 4D is a graphical representation showing various forces acting on the drill bit of FIG. 4C;

FIG. 5 is a schematic drawing in section with portions broken away of a rotary drill bit showing changes in bit side forces with respect to changes in dog leg severity (DLS) during drilling of a directional wellbore;

FIG. 6 is a side view of an example bit including a sleeve with full gage;

FIG. 7 is a side view of an example bit including a sleeve with under gage;

FIG. 8 is a side view of an example bit including a sleeve with tapered gage;

FIGS. 9A and 9B are views of an example embodiment of a bit including an eccentric sleeve;

FIGS. 10A, 10B, and 10C are views of an example embodiment of a bit including a sleeve with multiple eccentric segments and/or a bit including multiple eccentric sleeves; and

FIGS. 11A, 11B, 11C, and 11D are views of another example embodiment of a bit including a sleeve with multiple eccentric segments and/or a bit including multiple eccentric sleeves.

DETAILED DESCRIPTION

Reference to the following terms may be useful to the understanding and application of an eccentric sleeve for directional drilling systems.

The terms “axial taper” or “axially tapered” may be used in this application to describe various components or portions of a rotary drill bit, sleeve, near bit stabilizer, other downhole drilling tool and/or components such as a gage sleeve disposed at an angle relative to an associated bit rotational axis.

The term “bottom hole assembly” or “BHA” may be used in this application to describe various components and assemblies disposed proximate a rotary drill bit at the downhole end of a drill string. Examples of components and assemblies (not expressly shown) which may be included in a BHA include, but are not limited to, a bent sub, a downhole drilling motor, a near bit reamer, stabilizers and downhole instruments. A BHA may also include various types of well logging tools (not expressly shown) and other downhole drilling tools associated with directional drilling of a wellbore. Examples of such logging tools and/or directional drilling tools may include, but are not limited to, acoustic, neutron, gamma ray, density, photoelectric, nuclear magnetic resonance, rotary steering tools and/or any other commercially available well tool.

The terms “cutting element” and “cutting elements” may be used in this application to include, but are not limited to, various types of cutters, compacts, buttons, inserts and gage cutters satisfactory for use with a wide variety of rotary drill bits. Impact arrestors may be included as part of the cutting structure on some types of rotary drill bits and may sometimes function as cutting elements to remove formation materials from adjacent portions of a wellbore. Polycrystalline diamond compacts (PDC) and tungsten carbide inserts are often used to form cutting elements or cutters. Various types of other hard, abrasive materials may also be satisfactorily used to form cutting elements or cutters.

The term “cutting structure” may be used in this application to include various combinations and arrangements of cutting elements, impact arrestors and/or gage cutters formed on exterior portions of a rotary drill bit and/or sleeve. Some rotary drill bits and/or sleeves may include one or more blades extending from an associated bit body with cutters disposed of the blades. Such blades may also be referred to as “cutter blades.” Various configurations of blades and cutters may be used to form cutting structures for a rotary drill bit and/or sleeve.

The terms “downhole” and “uphole” may be used in this application to describe the location of various components of a rotary drill bit relative to portions of the rotary drill bit which engage the bottom or end of a wellbore to remove adjacent formation materials. For example an “uphole” component may be located closer to an associated drill string or BHA as compared to a “downhole” component which may be located closer to the bottom or end of the wellbore.

The term “gage” as used in this application may include a gage, gage segment, gage portion or any other portion of a rotary drill bit incorporating teachings of the present disclosure. Gages may be used to define or establish a nominal inside diameter of a wellbore formed by an associated rotary drill bit. A gage may be located downhole and adjacent to a gage sleeve. A gage, gage segment, gage portion or gage sleeve may include one or more layers of hardfacing material. One or more gage cutters, gage inserts, gage compacts or gage buttons may be disposed on or adjacent to a gage, gage segment, gage portion or gage sleeve.

The term “rotary drill bit” may be used in this application to include various types of fixed cutter drill bits, drag bits, matrix drill bits, steel body drill bits, roller cone drill bits, rotary cone drill bits and rock bits operable to form a wellbore extending through one or more downhole formations. Rotary drill bits and associated components formed having many different designs, configurations and/or dimensions. A rotary drill bit or other downhole drilling tool may be described as having multiple components, segments or portions. For example, one component of a drill bit may be described as a “cutting face profile” or “bit face profile” responsible for removal of formation materials to form an associated wellbore. For some types of drill bits the “cutting face profile” or “bit face profile” may be further divided into three segments such as “inner cutters or cone cutters,” “nose cutters” and/or “shoulder cutters.”

The term “straight hole” may be used to describe a wellbore or portions of a wellbore that extends at generally a constant angle relative to vertical. Vertical wellbores and horizontal wellbores are examples of straight holes.

The terms “slant hole” and “slant hole segment” may be used to describe a straight hole formed at a substantially constant angle relative to vertical. The constant angle of a slant hole is typically less than ninety degrees (90°) and greater than zero degrees)(0°.

Most straight holes such as vertical wellbores and horizontal wellbores with any significant length will have some variation from vertical or horizontal based in part on characteristics of associated drilling equipment used to form such wellbores. A slant hole may have similar variations depending upon the length and associated drilling equipment used to form the slant hole.

The term “kick off segment” may be used to describe a portion or section of a wellbore forming a transition between the end point of a straight hole segment and the first point where a desired dogleg severity or tilt rate is achieved. A kick off segment may be formed as a transition from a vertical wellbore to an equilibrium wellbore with a constant curvature or tilt rate. A kick off segment of a wellbore may have a variable curvature and a variable rate of change in degrees from vertical (variable tilt rate).

The term “directional wellbore” may be used in this application to describe a wellbore or portions of a wellbore that extend at a desired angle or angles relative to vertical. Such angles are greater than normal variations associated with straight holes. A directional wellbore sometimes may be described as a wellbore deviated from vertical.

Sections, segments and/or portions of a directional wellbore may include, but are not limited to, a vertical section, a kick off section, a building section, a holding section (sometimes referred to as a “tangent section”) and/or a dropping section. Vertical sections may have substantially no change in degrees from vertical. Build segments generally have a positive, constant rate of change in degrees. Drop segments generally have a negative, constant rate of change in degrees. Holding sections such as slant holes or tangent segments and horizontal segments may extend at respective fixed angles relative to vertical and may have substantially zero rate of change in degrees from vertical.

Transition sections formed between straight hole portions of a wellbore may include, but are not limited to, kick off segments, building segments and dropping segments. Such transition sections generally have a rate of change in degrees either greater than or less than zero. The rate of change in degrees may vary along the length of all or portions of a transition section or may be substantially constant along the length of all or portions of the transition section.

A building segment having a relatively constant radius and a relatively constant change in degrees from vertical (i.e., constant tilt rate) may be used to form a transition from vertical segments to a slant hole segment or horizontal segment of a wellbore. A dropping segment may have a relatively constant radius and a relatively constant change in degrees from vertical (constant tilt rate) may be used to form a transition from a slant hole segment or a horizontal segment to a vertical segment of a wellbore. For example, see FIG. 1A. Building segments and dropping segments may also be described as “equilibrium” segments.

The terms “dogleg severity” or “DLS” may be used to describe the rate of change in degrees of a wellbore from vertical during drilling of the wellbore. DLS is often measured in degrees per one hundred feet (°/100 ft). A straight hole, vertical hole, slant hole or horizontal hole will generally have a value of DLS of approximately zero. DLS may be positive, negative or zero.

Tilt angle (TA) may be defined as the angle in degrees from vertical of a segment or portion of a wellbore. A vertical wellbore has a generally constant tilt angle (TA) approximately equal to zero. A horizontal wellbore has a generally constant tilt angle (TA) approximately equal to ninety degrees) (90°.

Tilt rate (TR) may be defined as the rate of change of a wellbore in degrees (TA) from vertical per hour of drilling. Tilt rate may also be referred to as “steer rate.”

${TR} = \frac{({TA})}{t}$

Where t=drilling time in hours

Tilt rate (TR) of a drill bit may also be defined as DLS times rate of penetration (ROP).

TR=DLS×ROP/100=(degrees/hour)

Tilt rate and tilt angle may be used to plan, evaluate, or execute directional drilling. DLS of respective segments, portions or sections of a wellbore and corresponding tilt rate may be also used to conduct such planning, evaluation, or execution. Increasing the DLS capability of a drilling tool may increase the ability to directionally drill a wellbore with a greater range of angles.

The terms “downhole data” and “downhole drilling conditions” may include, but are not limited to, wellbore data, formation data, or drilling equipment operating data.

The terms “design parameters,” “operating parameters,” “wellbore parameters” and “formation parameters” may sometimes be used to refer to respective types of data used to simulate or effect drilling. The terms “parameter” and “parameters” may be used to describe a range of data or multiple ranges of data. The terms “operating” and “operational” may sometimes be used interchangeably.

Various teachings of the present disclosure directed towards certain of downhole drilling tools may also be used to design and/or select other types of downhole drilling tools. For example, a sleeve—such as an eccentric sleeve—located proximate a drill bit may function similar to a passive gage or an active gage.

One difference between a “passive gage” and an “active gage” may be that a passive gage will generally not remove formation materials from the sidewall of a wellbore or borehole while an active gage may at least partially cut into the sidewall of a wellbore or borehole during directional drilling. A passive gage may deform a sidewall plastically or elastically during directional drilling. Active gage cutting elements generally contact and remove formation material from sidewall portions of a wellbore. For active and passive gages the primary force is generally a normal force which extends generally perpendicular to the associated gage face either active or passive.

FIG. 1A is an illustration of an example directional drilling system 20 for drilling a wellbore 60. Directional drilling system 20 may be operable to form wellbores having a wide variety of profiles or trajectories. Directional drilling system 20 and wellbore 60 may be used to describe various features of the present disclosure with respect to use of an eccentric sleeve for directional drilling.

Directional drilling system 20 may include land drilling rig 22. However, teachings of the present disclosure may be applied to wellbores using drilling systems associated with offshore platforms, semi-submersible, drill ships and any other drilling system satisfactory for forming a wellbore extending through one or more downhole formations.

Drilling rig 22 and associated directional drilling equipment 50 may be located proximate well head 24. Drilling rig 22 also includes rotary table 38, rotary drive motor 40 and other equipment associated with rotation of drill string 32 within wellbore 60. Annulus 66 may be formed between the exterior of drill string 32 and the inside diameter of wellbore 60.

For some applications drilling rig 22 may also include top drive motor or top drive unit 42. Blow out preventers (not expressly shown) and other equipment associated with drilling a wellbore may also be provided at well head 24. One or more pumps 26 may be used to pump drilling fluid 28 from fluid reservoir or pit 30 to one end of drill string 32 extending from well head 24. Conduit 34 may be used to supply drilling mud from pump 26 to the one end of drilling string 32 extending from well head 24. Conduit 36 may be used to return drilling fluid, formation cuttings and/or downhole debris from the bottom or end 62 of wellbore 60 to fluid reservoir or pit 30. Various types of pipes, tube and/or conduits may be used to form conduits 34 and 36.

Drill string 32 may extend from well head 24 and may be coupled with a supply of drilling fluid such as pit or reservoir 30. Opposite end of drill string 32 may include a BHA 90 and drill bit 100 disposed adjacent to end 62 of wellbore 60.

At end 62 of wellbore 60 drilling fluid may mix with formation cuttings and other downhole debris proximate drill bit 100. The drilling fluid will then flow upwardly through annulus 66 to return formation cuttings and other downhole debris to well head 24. Conduit 36 may return the drilling fluid to reservoir 30. Various types of screens, filters and/or centrifuges (not expressly shown) may be provided to remove formation cuttings and other downhole debris prior to returning drilling fluid to pit 30.

Directional drilling system 20 may include various downhole drilling tools and components associated with a measurement while drilling (MWD) system that provides logging data and other information from the bottom of wellbore 60 to directional drilling equipment 50. As discussed later in more detail, directional drilling system 20 may include an eccentric sleeve, such as those embodied in FIGS. 9-11, for directional drilling.

Directional drilling equipment 50 may include one or more electronic devices configured to monitor and/or control the drilling of wellbore 60. Logging data and other information may be communicated from end 62 of wellbore 60 through drill string 32 using MWD techniques and converted to electrical signals at well surface 24. Electrical conduit or wires 52 may communicate the electrical signals to input device 54. The logging data provided from input device 54 may then be directed to a data processing system 56. Various displays 58 may be provided as part of directional drilling equipment 50. Printer 59 and associated printouts 59 a may also be used to monitor the performance of drilling string 32, BHA 90 and associated drill bit 100. Outputs 57 may be communicated to various components associated with operating drilling rig 22, to various remote locations to monitor and/or control the performance of directional drilling system 20, or to users simulating the drilling of wellbore 60.

Data processing system 56 may include a processor coupled to a memory. The processor may comprise, for example a microprocessor, microcontroller, digital signal processor (DSP), application specific integrated circuit (ASIC), or any other digital or analog circuitry configured to interpret and/or execute program instructions and/or process data. In some embodiments, the processor may interpret and/or execute program instructions and/or process data stored in the memory. Such program instructions or process data may constitute portions of software for carrying out simulation, monitoring, or control of the directional drilling described herein. The memory may include any system, device, or apparatus configured to hold and/or house one or more memory modules; for example, the memory may include read-only memory, random access memory, solid state memory, or disk-based memory. Each memory module may include any system, device or apparatus configured to retain program instructions and/or data for a period of time (e.g., computer-readable non-transitory media).

Teachings of the present disclosure may be used to simulate drilling a wide variety of vertical, directional, deviated, slanted and/or horizontal wellbores with drilling equipment containing an eccentric sleeve. Teachings of the present disclosure may include but are not limited to simulating drilling wellbore 60, designing drill bits for use in drilling wellbore 60 or selecting drill bits from existing designs for use in drilling wellbore 60.

Wellbore 60 may be generally described as a directional wellbore or a deviated wellbore having multiple segments or sections. Section 60 a of wellbore 60 may be defined by casing 64 extending from well head 24 to a selected downhole location. Remaining portions of wellbore 60 may be generally described as “open hole” or “uncased.”

Wellbore 60 may be generally described as having multiple sections, segments or portions with respective values of DLS. The tilt rate for drill bit 100 during formation of wellbore 60 may be a function of DLS for each segment, section or portion of wellbore 60 times the rate of penetration for drill bit 100 during formation of the respective segment, section or portion thereof. The tilt rate of drill bit 100 during formation of straight hole sections or vertical section 60 a and horizontal section 80 h (as illustrated in FIG. 4C) will be approximately equal to zero. The DLS capability, and consequently the tilt rate capability, of drilling equipment such as a downhole drilling tool for use in a directional drilling system 20—for example, a tool including drill bit 100—may be affected by the selection of an eccentric sleeve for directional drilling. For example, selection of an eccentric sleeve for directional drilling as embodied in FIGS. 9-11 may increase the DLS capability of the directional drilling system 20 including drill bit 100. Examples of different DLS values may be illustrated in sections 60 a-60 f.

Section 60 a extending from well head 24 may be generally described as a vertical, straight hole section with a value of DLS approximately equal to zero. When the value of DLS is zero, drill bit 100 will have a tilt rate of approximately zero during formation of the corresponding section of wellbore 60.

A first transition from vertical section 60 a may be described as kick off section 60 b. For some applications the value of DLS for kick off section 60 b may be greater than zero and may vary from the end of vertical section 60 a to the beginning of a second transition segment or building section 60 c. Building section 60 c may be formed with relatively constant radius 70 c and a substantially constant value of DLS. Building section 60 c may also be referred to as third section 60 c of wellbore 60.

Fourth section 60 d may extend from build section 60 c opposite from second section 60 b. Fourth section 60 d may be described as a slant hole portion of wellbore 60. Section 60 d may have a DLS of approximately zero. Fourth section 60 d may also be referred to as a “holding” section.

Fifth section 60 e may start at the end of holding section 60 d. Fifth section 60 e may be described as a “drop” section having a generally downward looking profile. Drop section 60 e may have relatively constant radius 70 e.

Sixth section 60 f may also be described as a holding section or slant hole section with a DLS of approximately zero. Section 60 f as shown in FIG. 1A is being formed by drill bit 100, BHA 90, drill string 32 and associated components of drilling system 20. Such components may include an eccentric sleeve.

FIG. 1B is an illustration of an example system operable to simulate drilling a directional wellbore. System 300 may calculate, for example, bit walk force, walk rate and walk angle based at least in part on bit cutter layout, bit gage geometry, sleeve size, sleeve geometry, hole size, hole geometry, rock compressive strength, inclination of formation layers, bit steering mechanism, bit rotational speed, penetration rate and dogleg severity. In one embodiment, sleeve size and sleeve geometry may include information regarding the eccentric nature of a sleeve to be used in drilling the directional wellbore. In another embodiment, dogleg severity may be calculated using the sleeve size and or sleeve geometry.

System 300 may include one or more processing resources 310 operable to run software and computer programs incorporating teachings of the present disclosure. Processing resource 310 may comprise, for example a general purpose computer, microprocessor, microcontroller, digital signal processor (DSP), application specific integrated circuit (ASIC), or any other digital or analog circuitry configured to interpret and/or execute program instructions and/or process data. The memory resource 320 may include any system, device, or apparatus configured to hold and/or house one or more memory modules; for example, the memory resource 320 may include read-only memory, random access memory, solid state memory, or disk-based memory. Each memory module may include any system, device or apparatus configured to retain program instructions and/or data for a period of time (e.g., computer-readable non-transitory media). One or more input devices 330 may be operate to supply data and other information to processing resource 310 and/or memory resource 320. A keyboard, keypad, touch screen and other digital input mechanisms may be used as an input device.

Display resource 340 may be operable to display both data input into processing resource 310 and the results of simulations and/or calculations performed therein. A copy of input data and results of such simulations and calculations may also be provided at printer 350.

For some applications, system 300 may be operably coupled with communication network 360 to accept inputs from remote locations and to provide the results of simulation and associated calculations to remote locations and/or facilities such as directional drilling equipment 50 shown in FIG. 1A.

FIG. 1C is a block diagram representing some of the inputs that may be used to simulate or cause forming a directional wellbore such as shown in FIG. 1A. Input 370 may include the type of rotary steering system such as point-the-bit or push-the bit. Input 370 may also include the drilling mode such as vertical, horizontal, slant hole, building, dropping, transition and/or kick-off Operational parameters 372 may include DLS, WOB, ROP, revolutions-per-minute (RPM) and other parameters. In one embodiment, DLS may be calculated given parameters, simulation, or testing results from using an eccentric sleeve. In another embodiment, WOB may be reduced by stick-slip vibration during directional drilling due associated with frictional torque due to contact between portions of drilling equipment—such as a sleeve or side of a bit—and the wellbore. In such embodiments, selection of an eccentric sleeve such as those embodied in FIGS. 9-11 may be made with consideration of such operational parameters for effective drilling of a wellbore.

Formation information 374 may include soft, medium or hard formation materials, multiple layers of formation materials, inclination of formation layers, the presence of hard stringers and/or the presence of concretions or very hard stones in one or more formation layers. Soft formations may include, but are not limited to, unconsolidated sands, clay, soft limestone and other downhole formations having similar characteristics. Medium formations may include, but are not limited to, calcites, dolomites, limestone and some shale formations. Hard formation materials may include, but are not limited to, hard shales, hard limestone and hard calcites.

Output 380 may include, but is not limited to, changes in WOB, TOB and/or any imbalances on associated cutting elements or cutting structures. Output 382 may include walk angle, walk force and/or walk rate of an associated drill bit. Outputs 384 may include required build rate, drop rate and/or steering forces required to form a desired wellbore profile. Output variations 388 may include variations in any of the previous outputs over the length of forming an associated wellbore.

Additional contributors may also be used to simulate and evaluate the performance of a drill bit and/or other downhole drilling tools in forming a directional wellbore. Contributors 390 may include, but are not limited to, the location and design of cone cutters, nose cutters, shoulder cutters and/or gage cutters. Contributors 392 may include the length/width of gage sleeves, taper of gage sleeves, number of gage sleeves, geometry of eccentric gage sleeves, axes of rotation of eccentric gage sleeves, circumferences and diameters of eccentric gage sleeves, heights and arrangements of eccentric gage sleeves, blade spiral and/or under gage dimensions of a drill bit or other downhole drilling tool.

Movement or motion of a drill bit and associated drilling equipment in three dimensions (3D) during formation of a segment, section or portion of a wellbore may be defined by a Cartesian coordinate system (X, Y, and Z axes) and/or a spherical coordinate system (two angles φ and θ and a single radius p) in accordance with teachings of the present disclosure. Examples of Cartesian coordinate systems are shown in FIGS. 2A and 3B. The location of downhole drilling equipment or tools and adjacent portions of a wellbore may be translated between a Cartesian coordinate system and a spherical coordinate system.

A Cartesian coordinate system generally includes a Z axis and an X axis and a Y axis which extend normal to each other and normal to the Z axis. See for example FIG. 2A. A Cartesian bit coordinate system may be defined by a Z axis extending along a rotational axis or bit rotational axis of the drill bit. See FIG. 2A. A Cartesian hole coordinate system (sometimes referred to as a “downhole coordinate system” or a “wellbore coordinate system”) may be defined by a Z axis extending along a rotational axis of the wellbore. See FIG. 3B. In FIG. 2A the X, Y and Z axes include subscript_((b)) to indicate a “bit coordinate system.” In FIGS. 3A, 3B and 3C the X, Y and Z axes include subscript_((h)) to indicate a “hole coordinate system.”

FIG. 2A is a schematic drawing showing an example drill bit 100. Drill bit 100 may include bit body 120 having a plurality of blades 128 with respective junk slots or fluid flow paths 140 formed therebetween. In one embodiment, drill bit 100 may be a rotary drill bit. A plurality of cutting elements 130 may be disposed on the exterior portions of each blade 128. Each blade 128 may include respective gage surface or gage portion 154. Gage surface 154 may be an active gage and/or a passive gage. Respective gage cutter 130 g may be disposed on each blade 128. A plurality of impact arrestors 142 may also be disposed on each blade 128. In one embodiment, drill bit 100 may be configured to be used with a downhole drilling tool including an eccentric sleeve such as those embodied in FIGS. 9-11.

Drill bit 100 may translate linearly relative to the X, Y and Z axes as shown in FIG. 2A (three (3) degrees of freedom). Drill bit 100 may also rotate relative to the X, Y and Z axes (three (3) additional degrees of freedom). As a result movement of drill bit 100 relative to the X, Y and Z axes as shown in FIGS. 2A and 2B, drill bit 100 may be described as having six (6) degrees of freedom. During drilling, these parameters may be expressed by WOB, bit walk forces, RPM, ROP, DLS, bend length (B_(L)) and azimuth angle of an associated tilt plane. Thus, factors that affect WOB and/or DLS in turn affect the movement of drill bit 100. In one embodiment, such factors may include the choice of an eccentric sleeve such as shown in FIGS. 9-11.

When sufficient force from drill string 32 has been applied to drill bit 100, cutting elements 130 will engage and remove adjacent portions of a downhole formation at bottom hole or end 62 of wellbore 60. Removing such formation materials will allow downhole drilling equipment including drill bit 100 and associated drill string 32 to move linearly relative to adjacent portions of wellbore 60.

Various kinematic parameters associated with forming a wellbore using a drill bit may be based upon RPM and ROP of the drill bit into adjacent portions of a downhole formation. Arrow 110 in FIG. 2A may be used to represent forces which move drill bit 100 linearly relative to rotational axis 104 a. Such linear forces typically result from weight applied to drill bit 100 by drill string 32, resulting in WOB. If there is no weight on drill bit 100, no axial penetration will occur at end or bottom hole 62 of wellbore 60.

Rotational force 112 may be applied to drill bit 100 by rotation of drill string 32. RPM of drill bit 100 may be a function of rotational force 112. Rotation speed of drill bit 100 is generally defined relative to the rotational axis of drill bit 100 which corresponds with Z axis 104.

Arrow 116 indicates rotational forces which may be applied to drill bit 100 relative to X axis 106. Arrow 118 indicates rotational forces which may be applied to drill bit 100 relative to Y axis 108. Rotational forces 116 and 118 may result from interaction between cutting elements 130 disposed on exterior portions of drill bit 100 and adjacent portions of bottom hole 62 during the forming of wellbore 60. Rotational forces applied to drill bit 100 along X axis 106 and Y axis 108 may result in tilting of drill bit 100 relative to adjacent portions of drill string 32 and wellbore 60.

FIG. 2B is a schematic drawing of drill bit 100 disposed within vertical section or straight hole section 60 a of wellbore 60. During the drilling of a vertical section or any other straight hole section of a wellbore, the bit rotational axis of drill bit 100 will generally be aligned with a corresponding rotational axis of the straight hole section. The incremental change or the incremental movement of drill bit 100 in a linear direction during a single revolution may be represented by ΔZ in FIG. 2B.

Rate of penetration of a drill bit is typically a function of both WOB and RPM. For some applications a downhole motor (not expressly shown) may be provided as part of BHA 90 to also rotate drill bit 100. The ROP of a drill bit is generally stated in feet per hour.

The axial penetration of drill bit 100 may be defined relative to bit rotational axis 104 a in an associated bit coordinate system. An equivalent side penetration rate or lateral penetration rate due to tilt motion of drill bit 100 may be defined relative to an associated hole coordinate system. Examples of a hole coordinate system are shown in FIGS. 3A, 3B and 3C.

FIGS. 3A, 3B and 3C are graphical representations of various kinematic parameters which may be satisfactorily used to model or simulate drilling segments or portions of a wellbore having a value of DLS greater than zero. In one embodiment, such kinematic parameters may be associated with the drilling of a wellbore by a downhole drilling tool with an eccentric sleeve. The values of the kinetic parameters may be affected by the effects upon DLS or WOB as caused by the choice of an eccentric sleeve such as those embodied in FIGS. 9-11.

FIG. 3A shows a schematic cross-section of drill bit 100 in two dimensions relative to a Cartesian bit coordinate system. The bit coordinate system is defined in part by X axis 106 and Y axis 108 extending from bit rotational axis 104 a. FIGS. 3B and 3C show graphical representations of drill bit 100 during drilling of a transition segment such as kick off segment 60 b of wellbore 60 in a Cartesian hole coordinate system defined in part by Z axis 74, X axis 76 and Y axis 78.

A side force is generally applied to a drill bit by an associated directional drilling system to form a wellbore having a desired profile or trajectory using the drill bit. For a given set of drilling equipment design parameters and a given set of downhole drilling conditions, a respective side force must be applied to an associated drill bit to achieve a desired DLS or tilt rate. Therefore, forming a directional wellbore using a point-the-bit directional drilling system, a push-the-bit directional drilling system or any other directional drilling system may be simulated by determining required bit side force to achieve desired DLS or tilt rate for each segment of a directional wellbore.

FIG. 3A shows side force 114 extending at angle 72 relative to X axis 106. Side force 114 may be applied to drill bit 100 by directional drilling system 20. Angle 72 (sometimes referred to as an “azimuth” angle) extends from rotational axis 104 a of drill bit 100 and represents the angle at which side force 114 will be applied to drill bit 100. For some applications side force 114 may be applied to drill bit 100 at a relatively constant azimuth angle.

Directional drilling systems such as drill bit steering unit 92 b shown in FIG. 4A may be used to either vary the amount of side force 114 or to maintain a relatively constant amount of side force 114 applied to drill bit 100. Directional drilling systems may also vary the azimuth angle at which a side force is applied to a drill bit to correspond with a desired wellbore trajectory or drill path. In one embodiment, the amount of side force 114 required to achieve a desired DLS or the ability to select a particular an azimuth angle may depend upon a choice of an eccentric sleeve such as those embodied in FIGS. 9-11.

During drilling of straight hole segments of wellbore 60, side forces applied to drill bit 100 may be substantially minimized (approximately zero side forces) or may be balanced such that the resultant value of any side forces will be approximately zero. Straight hole segments of wellbore 60 as shown in FIG. 1A include, but are not limited to, vertical section 60 a, holding section or slant hole section 60 d, and holding section or slant hole section 60 f. During formation of straight hole segments of wellbore 60, the primary direction of movement or translation of drill bit 100 will be generally linear relative to an associated longitudinal axis of the respective wellbore segment and relative to associated bit rotational axis 104 a.

During the drilling of portions of wellbore 60 having a DLS with a value greater than zero or less than zero, a side force (F_(s)) or equivalent side force may be applied to an associated drill bit to cause formation of corresponding wellbore segments 60 b, 60 c and 60 e.

For some applications such as when a push-the-bit directional drilling system is used with a drill bit, an applied side force may result in a combination of bit tilting and side cutting or lateral penetration of adjacent portions of a wellbore. For other applications such as when a point-the-bit directional drilling system is used with an associated drill bit, side cutting or lateral penetration may generally be small or may not even occur. When a point-the-bit directional drilling system is used with a drill bit, directional portions of a wellbore may be formed primarily as a result of bit penetration along an associated bit rotational axis and tilting of the drill bit relative to a wellbore axis.

Side force 114 may be adjusted or varied to cause associated cutting elements 130 to interact with adjacent portions of a downhole formation so that drill bit 100 will follow profile or trajectory 68 a, as shown in FIG. 3B, or any other desired profile. Respective tilting angles of drill bit 100 will vary along the length of trajectory 68 a. Arrow 174 corresponds with the variable tilt rate of drill bit 100 relative to vertical at any one location along trajectory 68 a. During movement of drill bit 100 along profile or trajectory 68 a, the respective tilt angle at each location on trajectory 68 a will generally increase relative to Z axis 74 of the hole coordinate system shown in FIG. 3B. For embodiments such as shown in FIG. 3B, the tilt angle at each point on trajectory 68 a will be approximately equal to an angle formed by a respective tangent extending from the point in question and intersecting Z axis 74. Therefore, the tilt rate will also vary along the length of trajectory 168.

During the formation of kick off segment 60 b and any other portions of a wellbore in which the value of DLS is either greater than zero or less than zero and is not constant, drill bit 100 may experience side cutting motion, bit tilting motion and axial penetration in a direction associated with cutting or removing of formation materials from the end or bottom of a wellbore.

For embodiments as shown in FIGS. 3A, 3B and 3C directional drilling system 20 may cause drill bit 100 to move in the same azimuth plane 170 during formation of kick off segment 60 b. FIGS. 3B and 3C show relatively constant azimuth plane angle 172 relative to the X axis 76 and Y axis 78. Arrow 114 as shown in FIG. 3A represents a side force applied to drill bit 100 by directional drilling system 20. Arrow 114 may generally extend normal to rotational axis 104 a of drill bit 100. Arrow 114 may also be disposed in tilt plane 170. A side force applied to a drill bit in a tilt plane by an associate drill bit steering unit or directional drilling system may also be referred to as a “steer force.”

During the formation of a directional wellbore such as shown in FIG. 3B, without consideration of bit walk, rotational axis 104 a of drill bit 100 and a longitudinal axis of BHA 90 may generally lie in tilt plane 170. Drill bit 100 may experience tilting motion in tilt plane 170 while rotating relative to rotational axis 104 a. Tilting motion may result from a side force or steer force applied to drill bit 100 by a directional steering unit. See FIGS. 4A and 4B. Tilting motion often results from a combination of side forces and/or axial forces applied to drill bit 100 by directional drilling system 20.

If drill bit 100 walks, either left toward X axis 76 or right toward Y axis 78, bit 100 will generally not remain in the same azimuth plane or tilt plane 170 during formation of kickoff segment 60 b. Arrow 177 as shown in FIGS. 3B and 3C represents a walk force which will cause drill bit 100 to “walk” left relative to tilt plane 170.

FIGS. 4A-4D are illustrations of various aspects of point-the-bit directional drilling systems. Such point-the-bit directional drilling systems may utilize a fulcrum point to be formed between an associated bit cutting structure or bit face profile and associated point-the-bit rotary steering system (RSS). The fulcrum point may be formed by a sleeve disposed uphole from the associated drill bit. In one embodiment, the fulcrum point may be formed by an eccentric sleeve such as those embodied in FIGS. 9-11. Such a fulcrum point may be formed by the interaction of a sleeve of a downhole drilling tool with a wellbore being drilled. Such contact may form the fulcrum point necessary to turn the bit to directional drill the wellbore. The ability to form a fulcrum further uphole may thus allow a sharper angle of directional drilling.

FIG. 4A shows portions of a downhole drilling tool disposed in a generally vertical section of wellbore 60 a as drill bit 100 b begins to form kick off segment 60 b. BHA 90 b may include drill bit steering unit 92 b which may provide one portion of a point-the-bit directional drilling system. A point-the-bit directional drilling system may usually generate a deflection which deforms portions of an associated drill string to direct an associated drill bit in a desired trajectory. There are several steering or deflection mechanisms associated with point-the-bit rotary steering systems. However, a common feature of point-the-bit RSS may be a deflection angle generated between the rotational axis of an associated drill bit and longitudinal axis of an associated wellbore.

Point-the-bit directional drilling systems may form a directional wellbore using a combination of axial bit penetration, bit rotation and bit tilting. Point-the-bit directional drilling systems may not produce side penetration in as high of magnitude as, for example, push-the-bit directional drilling systems. Examples of a point-the-bit directional drilling system are the Geo-Pilot® Rotary Steerable System and SlickBore® Matched Drilling Service available from Sperry Drilling Services at Halliburton Company.

Drill bit 100 b may extend from BHA 90 b to the end 62 of wellbore 60. Sleeve 61 may be included in drill bit 100 b or may be coupled to drill bit 100 b. In one embodiment, sleeve 61 may include one or more cutting blades. The number of blades on sleeve 61 may be different than the number of blades on drill bit 100 b. Bottom hole assembly 90 may be aligned with vertical axis 74 while rotary drill bit 100 is aligned with rate of penetration axis 55. Kick-off load 63 may be applied by the side wall of wellbore 60 on an uphole portion of drill bit 100 b to point-the-bit in the direction of rate of penetration axis 55. In a steering mode, the BHA 90 b causes more or less of kick-off load 63 to be applied to the uphole portion of the drill bit 100 b. The contact of drill bit 100 b at the point of kick-off load 63 acts as a fulcrum point.

FIG. 4B is a graphical representation showing various parameters associated with a point-the-bit directional drilling system. Steering unit 92 b may generally include bent subassembly 96 b. A wide variety of bent subassemblies may be satisfactorily used to allow drill string 32 to rotate drill bit 100 b while bent subassembly 96 b directs or points drill bit 100 b at a desired angle away from vertical axis 74. Bent subassembly 96 b may include sleeve 61 and/or bit 100 b.

Bend length 204 b may be a function of the distance between fulcrum point 65 and the end of drill bit 100 b. Bend length may be used as one of the inputs to simulate forming portions of a wellbore, and may be the distance from a fulcrum point of an associated bent subassembly to a furthest location on a “bit face” or “bit face profile” of an associated drill bit. The furthest location may sometimes be referred to as the extreme end of the associated drill bit.

Since bend length associated with a point-the-bit directional drilling system is usually relatively small (often less than 12 times associated bit size), most of the cutting action associated with forming a directional wellbore may be a combination of axial bit penetration, bit rotation and bit tilting. See FIG. 4A.

Some bent subassemblies have a constant “bent angle.” Other bent subassemblies have a variable or adjustable “bent angle.” Bend length 204 b is generally a function of the dimensions and configurations of associated bent subassembly 96 b. As previously noted, side penetration of drill bit will generally not occur in a point-the-bit directional drilling system. Arrow 200 represents the rate of penetration along rotational axis of drill bit 100 b.

FIGS. 4C and 4D show various forces associated with drill bit 100 b attached near sleeve 240 building an angle relative to horizontal segment 60 h of a wellbore. Uphole portion 242 of sleeve 240 may contact adjacent portions of horizontal segment 60 b to provide desired fulcrum point 155 for point-the-bit rotary steering system 92 b. Fulcrum point 155 may be utilized to apply directional force to steer the bit in directional drilling at a specified angle. The formation of fulcrum point 155 may allow steering of the bit 100 b.

The formation of fulcrum point 155 further uphole may allow a sharper angle of steering of the bit 100 b.

The bit face profile for drill bit 100 b in FIG. 4C may include a recessed portion or cone shaped with a plurality of cone cutters 130 c disposed therein. Each blade (not expressly shown) may include a respective nose segment which defines in part an extreme downhole end of drill bit 100 b. A plurality of nose cutters 130 n may be disposed on each nose segment. Each blade may also have a respective shoulder extending outward from the respective nose segment. A plurality of shoulder cutters 130 s may be disposed on each blade.

For some applications, drill bit 100 b and associated sleeve 240 may be divided into five zones for use in evaluating building an angle. Interaction of sleeve 240 with low side 68 in zone 235 may generate stick-slip vibration force 241, which may be proportional to the normal forces 184 g shown in FIG. 4D. Thus, the selection of type of sleeve 240 and the degree to which sleeve 240 engages the side of the wellbore may affect the stick-slip vibration force. The stick-slip vibration force may be in the opposite direction as the axial penetration, causing a reduction on WOB. The reduction in WOB may decrease the rate of drilling of drill bit 100 b.

In FIG. 4D, zone E may correspond with zone 235 of FIG. 4C. Reaction forces or normal forces 184 g shown in FIG. 4D may result from interactions with respective high sides 67 and low sides 68 of well bore of horizontal segment 60 h.

In one embodiment, simulations of forming a wellbore may be used to modify cutting elements, bit face profiles, gages, eccentric sleeves, and other characteristics of a drill bit or associated downhole drilling tools. In another embodiment, such modifications may be made to affect WOB, DLS, side forces, or other parameters. Such parameters may be affected by a choice of sleeves such as sleeve 240.

FIG. 5 is a schematic drawing showing drill bit 100 in solid lines in a first position associated with forming a generally vertical section of a wellbore. Drill bit 100 is also shown in dotted lines in FIG. 5 showing a directional portion of a wellbore such as kick off segment 60 a. The graph shown in FIG. 5 indicates that the amount of bit side force required to produce a tilt rate corresponding with the associated DLS will generally increase as the dogleg severity of the deviated wellbore increases. The shape of curve 194 as shown in FIG. 5 may be a function of downhole drilling tool design parameters and/or associated downhole drilling conditions. For example, the selection of sleeves for a downhole drilling tool may have impact upon DLS and WOB and consequently upon the ability to drill a wellbore. Sleeves used with drill bit 100 may be under gage, tapered gage, full gage, eccentric, or a combination thereof. In a specific example, selection of an embodiment of an eccentric sleeve as shown in FIGS. 9-11 for the downhole drilling tool may increase DLS capabilities, reducing the bit side force required to steer the bit and increasing the possible tilt rate.

FIG. 6 is a representation of an example drill bit 600 including a sleeve 604 with full gage. Sleeve 604 may have the same or approximately the same diameter as other portions of the drill bit 600, or as bit body 602. Bit body 602 may rotate around bit rotational axis 606 during drilling. In point-the-bit directional steering systems, the bit body 602 may have a long length in order to steer the bit. In one embodiment, the long length, shown in FIG. 6 as bit total length 608, may be greater than approximately 75% of the diameter of bit body 602, shown in FIG. 6 as bit total diameter 610. Such a relatively long bit length may be used to form a fulcrum point in the sleeve 604. A fulcrum point may be the point of contact between a portion of the bit body 602 or sleeve 604 and the side of the wellbore 60 as illustrated by fulcrum point 155 in FIG. 4C. The fulcrum point may be used to direct, point, or steer the bit in directional steering. In one embodiment, the fulcrum point may be formed at or near the uphole end of the sleeve 604. The ability to form an effective fulcrum point may be manifested by the DLS capabilities of the drill bit 600, which may indicate how large of an angle in a wellbore may be directionally drilled by the drill bit 600.

A sleeve such as sleeve 604 with the same or approximately the same diameter as the bit total diameter 610 may be referred to as a sleeve with full gage. If sleeve 604 has the same or approximately the same diameter as the bit total diameter 610, a fulcrum point in sleeve 604 may be formed with a high certainty. The ability to form a fulcrum point in sleeve 604 and specifically the ability to form a fulcrum point near the top of sleeve 604 may increase the DLS capability of drill bit 600. However, frictional torque due to contact between sleeve 604 and the wellbore that is being drilled may be quite high. This frictional torque may lead to stick-slip vibration, and may lead to a reduction in effective WOB during directional drilling. This reduction in effective WOB may decrease the penetration rate of the drill bit 600.

FIG. 7 is a representation of an example drill bit 700 including a sleeve 704 with under gage. Bit body 702 may rotate around bit rotational axis 706 during drilling. As described in accordance with FIG. 6, in point-the-bit directional steering systems, the bit body 702 may have a long length in order to steer the bit. In one embodiment, such a long length, shown in FIG. 7 as bit total length 712, may be greater than approximately 75% of the diameter of bit body 702, shown in FIG. 7 as bit total diameter 710. A relatively long bit length may be used to form a fulcrum point in the sleeve 704, which may be used to steer the bit. In one embodiment, the fulcrum point may be formed at or near the top of the sleeve 704.

In one embodiment, sleeve 704 may have a diameter that is smaller than the bit total diameter 710. A gap 708 having a uniform or nearly uniform distance along the length of sleeve 704 may be formed between the sleeve 704 and the wellbore. The gap 708 between the sleeve and the wellbore may cause a lack of contact between the sleeve and the wellbore. This lack of contact may reduce the ability to form a fulcrum point along the sleeve, or at the uphole end of the sleeve.

FIG. 8 is a representation of an example drill bit 800 including a sleeve 804 with tapered gage. Bit body 802 may rotate around bit rotational axis 806 during drilling. As described in accordance with FIG. 6, in point-the-bit directional steering systems, the bit body 802 may have a long length in order to steer the bit. In one embodiment, a long length, shown in FIG. 8 as bit total length 812, may be greater than approximately 75% of the diameter of bit body 802, shown in FIG. 8 as bit total diameter 810. This relatively long bit length may be used to form a fulcrum point in the sleeve 804, which may be used to steer the bit. In one embodiment, the fulcrum point may be formed at or near the top of the sleeve 804.

In one embodiment, sleeve 804 may have a diameter approximately equal to the bit total diameter 810 at the bottom of sleeve 804, which may taper towards the top of sleeve 804, at which point the sleeve 804 may have a diameter that is smaller than the bit total diameter 810. As a result, a gap 808 may exist between the sleeve 804 and the wellbore at the top of sleeve 804. The sleeve may be referred to as a sleeve with tapered gage. The gap 808 between the portions of the sleeve and the wellbore may cause a lack of contact between these portions of the sleeve and the wellbore. The lack of contact may reduce the ability to form a fulcrum point along the sleeve, or at the uphole end of the sleeve.

In sleeves such as sleeve 704 and sleeve 804, contact with the wellbore may be reduced. Consequently, stick-slip vibration may be reduced when compared to full gage sleeves such as sleeve 604, which may have greater contact with the wellbore than sleeves 704 and 804. A reduction in stick-slip vibration may reduce friction forces such as stick-slip vibration force 241 in FIG. 4C. The reduction in stick-slip vibration force 241 may maintain higher levels of WOB, thus effecting greater rates of drilling. However, returning to FIGS. 7 and 8, because sleeves 704 and 804 have under or tapered gages, contact with the wellbore wall by the sleeve is reduced. Such contact may be used to form a fulcrum point. Consequently, the ability of sleeves 704 and 804 to form a fulcrum point, and specifically a fulcrum point near the top of sleeve 704 and sleeve 804 may be also be reduced. The fulcrum point may be illustrated, for example, by fulcrum point 155 of FIG. 4C.

Forming a fulcrum point in a downhole drilling tool, and specifically near the top of a sleeve in the downhole drilling tool, may be used to increase the ability to directionally drill a borehole with the downhole drilling tool. The DLS capabilities of a downhole drilling tool such as 600, 700, or 800 may be directly related to the ability to steer the downhole drilling tool in greater angles. The greater the DLS capability of a downhole drilling tool, the greater the drilling may be tilted for the purposes of directional drilling.

Consequently, the design of a sleeve may affect the DLS capabilities of a given downhole drilling tool. As described above, in a full gage drill bit such as 600, DLS capabilities may be better retained with sleeve 604 having a diameter approximately equal to the bit total diameter 610. However, in drill bit 700 or drill bit 800, the under gage or tapered gage may significantly reduce the dogleg capability of the downhole drilling tool because the ability to form a fulcrum point—specifically, a fulcrum point at or near the top of the sleeve—has been reduced.

FIG. 9A is a side view of an example embodiment of a drill bit 900 including an eccentric sleeve 904. Drill bit 900 may be designed, simulated, and/or implemented in any suitable fashion, including according to the teachings of FIGS. 1-5. For example, drill bit 900 may implement the sleeve 61 and/or bit 100 b of FIG. 4. Drill bit 900 may include a bit body 902 rotating around a bit rotational axis 906. In one embodiment, eccentric sleeve 904 may be mass balanced around a geometrical axis 908. In another embodiment, eccentric sleeve 904 may be mass balanced around bit rotational axis 906. Eccentric sleeve 904 may be implemented by any drilling sleeve sufficient to fulfill one or more teachings of this disclosure. In one embodiment, eccentric sleeve 904 may be implemented by a drilling sleeve located at an offset from bit rotational axis 906. In another embodiment, eccentric sleeve 904 may be offset from bit rotational axis 906 in terms of the geometrical axis 908 being offset from bit rotational axis 906 by a distance Δa. Bit body 902 and eccentric sleeve 904 may be configured to rotate around bit rotational axis 906. As drill bit 900 rotates during drilling, one portion of eccentric sleeve 904 may contact the surface of the wellbore 60, and another portions of eccentric sleeve 904 located approximately one hundred eighty degrees (180°) from the first portion may be separated from the wellbore 60 by a gap having a distance. This distance, ΔA, may be approximately equal to two times Δa, the distance of the offset between the sleeve geometrical axis 908 and bit rotational axis 906.

FIG. 9B is a cross-sectional view from a vertical perspective of an example embodiment of a drill bit 900 as shown in FIG. 9A including an eccentric sleeve 904 and a bit body 902. Eccentric sleeve 904 may be smaller in diameter than bit body 902. Eccentric sleeve 904 may be aligned at the edge of the circumference of bit body 902 such that a portion of the exterior of eccentric sleeve 904 is aligned with a portion of the exterior of bit body 902. Eccentric sleeve 904 might not extrude past the exterior of bit body 902. Bit body 902 may include a bit rotational axis that may correspond to the location of the bit rotational axis 906 of FIG. 9A as it passes through the cross-section of bit body 902. Eccentric sleeve 904 may include a geometrical axis that may correspond to the location of the geometrical axis 908 of FIG. 9A as it passes through the cross-section of eccentric sleeve 904. The offset of the eccentric sleeve 904, Δa, may be equal to the distance between geometrical axis 908 and bit rotational axis 906. Eccentric sleeve 904 may be offset from bit body 902 such that only a portion of eccentric sleeve 904 contacts the surface of the wellbore 60 created by bit body 902. During rotation of bit 900, a portions of eccentric sleeve 904 may contact the surface of the wellbore 60 and, approximately one-hundred eighty degrees (180°) from the point of contact, a gap having a distance of ΔA=2*Δa may be formed between the surface of the wellbore 60 and the eccentric sleeve 904.

In operation, the rotation of a downhole drilling tool including an eccentric sleeve, for example, as illustrated in FIG. 9 during drilling may reduce frictional torque, reduce stick-slip vibration, and/or increase DLS capability. A downhole drilling tool including an eccentric sleeve may rotate to operate an associated bit. During drilling of a wellbore 60 using directional drilling system 20 as illustrated in FIG. 1A, a portion of the eccentric sleeve 904 may come into contact with the surface of the wellbore 60, providing a fulcrum point on at least a portion of the eccentric sleeve 904 at least one time during a single revolution of bit 900. For example, drill bit 900 may rotate while engaging bit body 902 during directional drilling. Eccentric sleeve 904 may contact the surface of the wellbore 60 sufficiently to establish a fulcrum point on a certain percentage of the sleeve's surface area during a given revolution of the downhole drilling tool. The percentage of the sleeve's surface area may depend upon the offset Δa, the diameter of bit body 902, and the angle of directional drilling. Simultaneously, the contact area with the wellbore 60 at any instance in time may be less than the contact in a downhole drilling tool with a full gage sleeve, thus, reducing stick-slip vibration. Thus, the DLS capabilities of a downhole drilling tool using an eccentric sleeve may be increased compared to a downhole drilling tool using a tapered or under gage sleeve, while also providing reduced frictional torque and/or stick-slip vibration.

FIG. 10A is a side view of an example embodiment of a drill bit 1000 including a sleeve with multiple eccentric segments and/or a bit including multiple eccentric sleeves. Drill bit 1000 may be designed, simulated, and/or implemented in any suitable fashion, including according to the teachings of FIGS. 1-5. For example, drill bit 1000 may implement the sleeve 61 and/or bit 100 b of FIG. 4. Drill bit 1000 may include a bit body 1002 configured to rotate around a bit rotational axis 1006. In one embodiment, drill bit 1000 may include a sleeve with one or more eccentric sleeve segments. In another embodiment, drill bit 1000 may include one or more eccentric sleeves. For example, drill bit 1000 may include a first eccentric sleeve 1004 and a second eccentric sleeve 1010. In one embodiment, eccentric sleeve 1004 may be mass balanced around a geometrical axis 1008 and eccentric sleeve 1010 may be mass balanced around a geometrical axis 1012. In another embodiment, each of eccentric sleeves 1004 and 1010 may be individually mass balanced around bit rotational axis 1006. In yet another embodiment, eccentric sleeves 1004 and 1010 together may be mass balanced around bit rotational axis 1006. Eccentric sleeves 1004 and 1010 may be implemented by any drilling sleeves sufficient to fulfill one or more teachings of this disclosure. Drill bit 1000 and its components, such as bit body 1002 and eccentric sleeves 1004 and 1010 may be configured to rotate as a single body around bit rotational axis 1006.

In one embodiment, eccentric sleeve 1004 may be implemented by a drilling sleeve or drilling sleeve segment located at an offset from bit rotational axis 1006. Eccentric sleeve 1004 may be offset from bit rotational axis 1006 in terms of the geometrical axis 1008 being offset from bit rotational axis 1006 by a distance Δa. Eccentric sleeve 1010 may be implemented by a drilling sleeve or drilling sleeve segment located at an offset from bit rotational axis 1006. Eccentric sleeve 1010 may be offset from bit rotational axis 1006 in terms of a geometrical axis 1012 being offset from bit rotational axis 1006 by a distance Δb. The diameter of eccentric sleeves 1004 and 1010 may be smaller than the diameter of bit 1002. Eccentric sleeves 1004 and 1010 may be arranged at opposite sides of drill bit 1000. Eccentric sleeve 1004 and eccentric sleeve 1010 may be arranged such that a portion of eccentric sleeve 1004 is aligned with a first portion of bit body 1002 and a portion of eccentric sleeve 1010 is aligned with a second portion of bit body 1002, where the first and second portions of bit body 1002 are located approximately 180° from each other. Eccentric sleeves 1004 and 1010 may be arranged vertically on top of one another.

As drill bit 1000 rotates during drilling, one portion of eccentric sleeve 1004 may contact the surface of the wellbore 60 and another portion of eccentric sleeve 1004 located approximately 180° from the first portion may be separated from the surface of the wellbore 60 by a gap having a distance of ΔA. The distance of ΔA may be approximately equal to two times Δa, the distance of the offset between the sleeve geometrical axis 1008 and bit rotational axis 1006. Additionally as drill bit 1000 rotates, one portion of eccentric sleeve 1010 may be in contact with the surface of the wellbore 60 and another portion of eccentric sleeve 1010 located approximately 180° from the first portion may be separated from the surface of the wellbore 60 by a gap having a distance of ΔB. The distance of ΔB may be equal to two times Δb, the distance of the offset between the sleeve geometrical axis 1012 and bit rotational axis 1006. In one embodiment, if the offset of eccentric sleeve 1004 (Δa) and the offset of eccentric sleeve 1010 (Δb) are approximately equal, then the distances between the respective sleeves and the wellbore 60 wall—ΔA and ΔB—may also be approximately equal.

FIGS. 10B and 10C are cross-sectional views from a vertical perspective of an example embodiment of a drill bit 1000 as shown in FIG. 10A including a sleeve with multiple eccentric segments and/or a bit with multiple eccentric sleeves. FIG. 10B illustrates the position of eccentric sleeve 1004 relative to bit body 1002, and FIG. 10C illustrates the position of eccentric sleeve 1010 relative to bit body 1002. Eccentric sleeves 1004 and 1010 may be smaller in diameter than bit body 1002. Bit body 1002 may include a bit rotational axis 1006 that may correspond to the location of the bit rotational axis 1006 of FIG. 10A as it passes through the cross-section of bit body 1002. Eccentric sleeves 1004 and 1010 may be aligned at the edge of the circumference of bit body 1002 such that a portion of each of the exterior of eccentric sleeves 1004 and 1010 are aligned with portions of the exterior of bit body 1002. Eccentric sleeves 1004 and 1010 might not extrude past the exterior of bit body 1002.

Eccentric sleeve 1004 may include a geometrical axis 1008 that corresponds to the location of the geometrical axis 1008 of eccentric sleeve 1004 of FIG. 10A as it passes through the cross-section of eccentric sleeve 1004 in FIG. 10B. The offset of eccentric sleeve 1004, Δa, may be approximately equal to the distance between geometrical axis 1008 and bit rotational axis 1006. Eccentric sleeve 1004 may be offset from bit body 1002 such that only a portion of eccentric sleeve 1004 contacts the surface of the wellbore 60 created by bit body 1002. During rotation, a portion of eccentric sleeve 1004 may contact the surface of the wellbore 60 and, approximately 180° from the point of contact, a gap having a distance of 2*Δa (ΔA) may be formed between the surface of the wellbore 60 and eccentric sleeve 1004.

Eccentric sleeve 1010 may include a geometrical axis 1012. Geometrical axis 1012 may correspond to the location of the geometrical axis 1012 of eccentric sleeve 1010 of FIG. 10A as it passes through the cross-section of eccentric sleeve 10 in FIG. 10C. The offset of eccentric sleeve 1010, Δb, may be approximately equal to the distance between geometrical axis 1012 and bit rotational axis 1006. Eccentric sleeve 1010 may be offset from bit body 1002 such that a portion of eccentric sleeve 1010 contacts the surface of the wellbore 60 created by bit body 1002. During rotation, a portion of eccentric sleeve 1010 may contact the surface of the wellbore 60 and, approximately 180° from the point of contact, a gap having a distance of 2*Δb (ΔB) may be formed between the surface of the wellbore 60 and eccentric sleeve 1010. In one embodiment, eccentric sleeves 1004 and 1010 may be arranged so that they each contact the wellbore 60 approximately 180° apart from each other.

In operation, the rotation of a downhole drilling tool or bit including eccentric sleeves such as those in FIG. 10 during drilling may reduce frictional torque, reduce stick-slip vibration, and/or increase DLS capability. A downhole drilling tool including eccentric sleeves or a sleeve with eccentric segments may rotate to operate an associated bit. During drilling of a wellbore 60 using directional drilling system 20 as illustrated in FIG. 1A, a portion of each eccentric sleeve may come into contact with surface of the wellbore 60, providing a fulcrum point on at least a portion of the eccentric sleeves during a single revolution of the bit.

For example, drill bit 1000 may rotate while engaging bit body 1002 during directional drilling. Eccentric sleeves 1004 and 1010 may contact the surface of the wellbore 60 sufficiently to establish a fulcrum point with a certain percentage of the sleeve's surface area during a given revolution. The percentage of the sleeve's surface area may depend upon offsets Δa and Δb, the diameter of bit body 1002, and the angle of directional drilling. For example, a downhole drilling tool such as those embodied by drill bit 1000 or using bit body 1002, which include dual eccentric sleeves, may be able to establish a fulcrum point at least twice during the a single revolution of the bit. Simultaneously, the contact area with the wellbore 60 at any instance in time may be less than the contact in a downhole drilling tool with a full gage sleeve, thus reducing stick-slip vibration. Thus, the DLS capabilities of a downhole drilling tool including two offset eccentric sleeves or sleeve segments may be increased compared to a downhole drilling tool using a tapered or under gage sleeve, while also providing reduced frictional torque and/or stick-slip vibration.

FIG. 11A is a side view of another example embodiment of a drill bit 1100 including a sleeve with multiple eccentric segments and/or a drill bit with multiple eccentric sleeves. Drill bit 1100 may be designed, simulated, and/or implemented in any suitable fashion, including according to the teachings of FIGS. 1-5. For example, drill bit 1000 may implement the sleeve 61 and/or bit 100 b of FIG. 4. Drill bit 1100 may contain a bit body 1102 configured to rotate around a bit rotational axis 1106. In one embodiment, drill bit 1100 may include a sleeve with one or more eccentric sleeve segments. In another embodiment, drill bit 1100 may include one or more eccentric sleeves. For example, drill bit 1100 may include eccentric sleeves, including a first eccentric sleeve 1103, a second eccentric sleeve 1104, and a third eccentric sleeve 1105. In one embodiment, eccentric sleeves 1103, 1104 and 1105 may each be mass balanced around its own geometrical axis (not shown). In another embodiment, eccentric sleeves 1103, 1104 and 1105 may each be mass balanced around bit rotational axis 1106. In yet another embodiment, eccentric sleeves 1103, 1104 and 1105 may together be mass balanced around bit rotational axis 1106. Eccentric sleeves 1103, 1104 and 1105 may be implemented by any drilling sleeves sufficient to fulfill one or more teachings of this disclosure. Drill bit 1100 and its components, such as bit body 1102, eccentric sleeves 1103, 1104 and 1105 may be configured to rotate as a single body around bit rotational axis 1106. Eccentric sleeves 1103, 1104 and 1105 may be arranged on top of one another in any suitable order.

In one embodiment, eccentric sleeve 1103 may be implemented by a drilling sleeve or drilling sleeve segment located at an offset from bit rotational axis 1106. Eccentric sleeve 1103 may be offset from bit rotational axis 1106 in terms of its geometrical axis (not shown) being offset from bit rotational axis 1106 by a distance Δa (not shown). Eccentric sleeve 1104 may be implemented by a drilling sleeve or drilling sleeve segment located at an offset from bit rotational axis 1106. Eccentric sleeve 1104 may be offset from bit rotational axis 1106 in terms of its geometrical axis (not shown) being offset from bit rotational axis 1106 by a distance Δb (not shown). Eccentric sleeve 1105 may be implemented by a drilling sleeve or drilling sleeve segment located at an offset from bit rotational axis 1106. Eccentric sleeve 1105 may be offset from bit rotational axis 1106 in terms of its geometrical axis (not shown) being offset from bit rotational axis 1106 by a distance Δc (not shown). The diameters of eccentric sleeves 1103, 1104, and 1105 may each be smaller than the diameter of bit 1106. Eccentric sleeves 1103, 1104, and 1105 may be spaced equally or nearly equally apart around the outer circumference of the drill bit 1100 or bit body 1102. In one embodiment, eccentric sleeves 1103, 1104, and 1105 may be spaced approximately 120° apart. Eccentric sleeves 1103, 1104 and 1105 may be arranged such that a portion of eccentric sleeve 1103 is aligned with a first portion of bit body 1102, a portion of eccentric sleeve 1104 is aligned with a second portion of bit body 1102, and a portion of eccentric sleeve 1105 is aligned with a third portion of bit body 1102. The first, second, and third portions of bit body 1102 may be located approximately 120° apart. Eccentric sleeves 1103, 1104 and 1105 may be arranged vertically on top of one another.

As drill bit 1100 rotates during drilling, one portion of eccentric sleeve 1103 may contact the surface of the wellbore 60, and another portion of eccentric sleeve 1103 located approximately 180° from the first portion may be separated from the surface of the wellbore 60 by a gap having a distance of ΔA (not shown). Such a distance of ΔA may be approximately equal to two times Δa, the distance of the offset between the eccentric sleeve 1103 geometrical axis (not shown) and bit rotational axis 1106. Additionally as drill bit 1100 rotates, one portion of eccentric sleeve 1104 may contact the surface of the wellbore 60 and another portion of eccentric sleeve 1104 located approximately 180° from the first portion may be separated from the surface of the wellbore 60 by a gap having a distance of ΔB (not shown). Such a distance of ΔB may be approximately equal to two times Δb, the distance of the offset between the eccentric sleeve 1104 geometrical axis (not shown) and bit rotational axis 1106. One portion of eccentric sleeve 1105 may contact the surface of the wellbore 60 and another portion of eccentric sleeve 1105 located approximately 180° from the first portion may be separated from the surface of the wellbore 60 by a gap having a distance of ΔC (not shown). Such a distance of ΔC may be approximately equal to two times Δc, the distance of the offset between its geometrical axis (not shown) and bit rotational axis 1106. In one embodiment, if the offsets of eccentric sleeves 1103, 1104 and 1105 are approximately equal then the distances between the respective sleeves and the wellbore 60 wall—ΔA and ΔB and ΔC—may be approximately equal.

FIGS. 11B, 11C, and 11D are cross-sectional views from a vertical perspective of an example embodiment of a drill bit as shown in FIG. 11A including a sleeve with multiple eccentric segments and/or a bit including multiple eccentric sleeves. FIG. 11B illustrates the position of eccentric sleeve 1103 relative to bit body 1102, FIG. 11C illustrates the position of eccentric sleeve 1104 relative to bit body 1102, and FIG. 11D illustrates the position of eccentric sleeve 1105 relative to bit body 1102. Eccentric sleeves 1103, 1104, and 1105 may each be smaller in diameter than bit body 1102. Bit body 1102 may include a bit rotational axis 1106. Bit rotational axis 1106 may correspond to the location of the bit rotational axis 1106 of FIG. 11A as it passes through the cross-section of bit body 1102. Eccentric sleeves 1103, 1104 and 1105 may be aligned at the edge of the circumference of bit body 1102 such that a portion of each of the exterior of eccentric sleeves 1103, 1104 and 1105 are aligned with portions of the exterior of bit body 1102. Eccentric sleeves 1103, 1104 and 1105 might not extrude past the exterior of bit body 1002.

Eccentric sleeve 1103 may include a geometrical axis 1108. Geometrical axis 1108 may correspond to the location of the geometrical axis (not shown) of eccentric sleeve 1103 of FIG. 11A as it passes through the cross-section of eccentric sleeve 1103. The offset of eccentric sleeve 1103, Δa, may be approximately equal to the distance between geometrical axis 1108 and bit rotational axis 1106. Eccentric sleeve 1103 may be offset from bit body 1102 such that only a portion of eccentric sleeve 1103 contacts the surface of the wellbore 60 created by bit body 1102. During rotation, a portion of eccentric sleeve 1103 may contact the surface of the wellbore 60, and, approximately 180° from the point of contact, a gap having a distance of 2*Δa (ΔA) may be formed between the surface of the wellbore 60 and eccentric sleeve 1103.

Eccentric sleeve 1104 may include a geometrical axis 1112. Geometrical axis 1112 may correspond to the location of the geometrical axis (not shown) of eccentric sleeve 1104 of FIG. 11A as it passes through the cross-section of eccentric sleeve 1104. The offset of eccentric sleeve 1104, Δb, may be approximately equal to the distance between geometrical axis 1112 and bit rotational axis 1106. Eccentric sleeve 1104 may be offset from bit body 1102 such that only a portion of eccentric sleeve 1104 contacts the surface of the wellbore 60 created by bit body 1102. During rotation, a portion of eccentric sleeve 1104 may contact the surface of the wellbore 60 and, approximately 180° from the point of contact, a gap having a distance of 2*Δb (ΔB) may be formed between the surface of the wellbore 60 and eccentric sleeve 1104.

Eccentric sleeve 1105 may include a geometrical axis 1116. Geometrical axis 1116 may correspond to the location of the geometrical axis (not shown) of eccentric sleeve 1105 of FIG. 11A as it passes through the cross-section of eccentric sleeve 1105. The offset of eccentric sleeve 1105, Δc, may be approximately equal to the distance between geometrical axis 1116 and bit rotational axis 1106. Eccentric sleeve 1105 may be offset from bit body 1102 such that only a portion of eccentric sleeve 1105 contacts the surface of wellbore 60 created by bit body 1102. During rotation, a portion of eccentric sleeve 1105 may contact the surface of the wellbore 60 and, approximately 180° from the point of contact, a gap having a distance of 2*Δc (ΔC) may be formed between the surface of the wellbore 60 and eccentric sleeve 1105.

Eccentric sleeves 1103, 1104, and 1105 may be arranged around the circumference of the bit body 1102 or downhole drilling tool in any suitable fashion. In one embodiment, eccentric sleeves 1103, 1104, and 1105 may be arranged around the circumference of the bit body 1102 or downhole drilling tool in equal or nearly equal distribution. In such an embodiment, eccentric sleeves 1103, 1104, and 1105 may be arranged around the circumference of the bit body 1102 or downhole drilling tool so that they each contact the surface of the wellbore 60 approximately 120° apart from each other. For example, eccentric sleeve 1103 may be arranged at 0°, eccentric sleeve 1104 may be arranged at approximately 120°, and eccentric sleeve 1105 may be arranged at approximately 240° around the circumference of bit body 1102. During drilling of a wellbore 60 using directional drilling system 20 as illustrated in FIG. 1A, a portion of each sleeve may come into contact with the surface of the wellbore 60, providing a fulcrum point on at least a portion of the eccentric sleeves during a single revolution of the bit.

In operation, the rotation of a downhole drilling tool or bit including triple eccentric sleeves such as those in FIG. 11 during drilling may reduce frictional torque, reduce stick-slip vibration, and/or increase DLS capability. A downhole drilling tool including triple eccentric sleeves or a sleeve with triple eccentric portions may rotate to operate an associated bit. During such activity while attempting directional drilling, a portion of each of the eccentric sleeves may contact the surface of the wellbore 60 during a revolution of the bit. Each such contact may provide a portion in which a fulcrum point may be located during a revolution of the bit. Eccentric sleeves 1103, 1104, and 1105 may each contact the surface of the wellbore 60 sufficiently to establish a fulcrum point with a certain percentage of the sleeve's surface area during a given revolution. Such a percentage of the sleeve's surface area may depend upon Δa, Δb, and Δc, the size of bit body 1102, and the angle of directional drilling. In one example, a triple eccentric sleeve such as those of drill bit 1100 may be able to establish a fulcrum point at least three times during a single revolution of the bit. Simultaneously, the contact area with the wellbore 60 at any instance in time may be much less than such contact in a downhole drilling tool with a full gage, thus reducing stick-slip vibration. The reduction in stick-slip vibration may maintain higher levels of WOB and subsequent drilling rates. Thus, the DLS capabilities of such a downhole drilling tool including three offset eccentric sleeves or sleeve segments may be increased compared a downhole drilling tool using a tapered or under gage sleeve, while also providing reduced frictional torque and/or stick-slip vibration.

Although the present disclosure and its advantages have been described in detail, it should be understood that various changes, substitutions and alternations can be made herein without departing from the spirit and scope of the disclosure as defined by the following claims. 

What is claimed is:
 1. A drill bit comprising: a bit body configured to rotate about a bit rotational axis; a first sleeve coupled to the bit body at an uphole portion of the bit body, the first sleeve: having a smaller diameter than the bit body; and having a portion aligned with a first edge portion of the bit body, the first edge portion located on the circumference of the bit body.
 2. The drill bit of claim 1 wherein the first sleeve is configured to form a fulcrum point for directional drilling at least once during a revolution of the bit body during formation of a wellbore.
 3. The drill bit of claim 2, wherein the first sleeve is further configured to contact a portion of the wellbore at a first point on the circumference of the first sleeve, and the fulcrum point is formed at the portion of the first sleeve contacting the wellbore.
 4. The drill bit of claim 3, wherein the first sleeve is further configured to form a gap between the wellbore and a second point on the first sleeve, the second point approximately one-hundred-eighty degrees along the circumference of the first sleeve from the first point.
 5. The drill bit of claim 1 wherein: the first sleeve comprises a first geometrical axis, the first geometrical axis located parallel to the bit rotational axis; and the first geometrical axis and the bit rotational axis are separated by a first distance.
 6. The drill bit of claim 5, wherein the first sleeve is mass balanced around the bit rotational axis.
 7. The drill bit of claim 1, further comprising a second sleeve, the second sleeve: having a smaller diameter than the bit body; and having a portion aligned with a second edge portion of the bit body, the second edge portion on the circumference of the bit body.
 8. The drill bit of claim 7, wherein: the first sleeve is further configured to form a fulcrum point for directional drilling a wellbore at least once during a revolution of the bit body; and the second sleeve is further configured to form the fulcrum point for directional drilling at least once during a revolution of the bit body.
 9. The drill bit of claim 8, wherein: the first sleeve is further configured to contact a portion of the wellbore at a first point on the circumference of the first sleeve; the second sleeve is further configured to contact the portion of the wellbore at a first point on the circumference of the second sleeve; and the fulcrum point is formed at the portion of the first sleeve contacting the wellbore and at the portion of the second sleeve contacting the wellbore during a revolution of the drill bit.
 10. The drill bit of claim 9, wherein during contact by the first sleeve with the wellbore, the second sleeve is configured to form a gap, the gap formed between the wellbore and the second sleeve, the gap located at the portion of the wellbore in contact with the first sleeve.
 11. The drill bit of claim 7, wherein the first sleeve and the second sleeve are coupled together.
 12. The drill bit of claim 7, wherein the first sleeve and the second sleeve are spaced equidistantly from each other along the circumference of the bit body from each other.
 13. The drill bit of claim 7, wherein the first sleeve and the second sleeve are spaced approximately one-hundred-eighty degrees from each other along the circumference of the bit body.
 14. The drill bit of claim 7, wherein: the second sleeve comprises a second geometrical axis, the second geometrical axis parallel with the bit rotational axis; the second geometrical axis and the bit rotational axis are separated by a second distance; and the first distance and the second distance are approximately equal.
 15. The drill bit of claim 7, wherein the first sleeve and the second sleeve rotate around the bit rotational axis.
 16. The drill bit of claim 7, further comprising a third sleeve, the third sleeve: having a smaller diameter than the bit body; and aligned at the edge of the circumference of the bit body.
 17. The drill bit of claim 16, wherein: the first sleeve is configured to form a fulcrum point for directional drilling a wellbore at least once during a revolution of the bit body; the second sleeve is configured to form the fulcrum point for directional drilling at least once during a revolution of the bit body; and the third sleeve is configured to form the fulcrum point for directional drilling at least once during a revolution of the bit body
 18. The drill bit of claim 17, wherein: the first sleeve is further configured to contact a portion of the wellbore at a first point on the circumference of the first sleeve; the second sleeve is further configured to contact the portion of the wellbore at a first point on the circumference of the second sleeve; the third sleeve is further configured to contact the portion of the wellbore at a first point on the circumference of the third sleeve; and the fulcrum point is formed at the portion of the first sleeve contacting the wellbore, at the portion of the second sleeve contacting the wellbore, and at the portion of the third sleeve contacting the wellbore during a revolution of the drill bit.
 19. The drill bit of claim 18, wherein during contact by the first sleeve with the wellbore: the second sleeve is configured to form a first gap, the first gap formed between the wellbore and the second sleeve, the first gap located at the portion of the wellbore in contact with the first sleeve; and the third sleeve is configured to form a second gap, the second gap formed between the wellbore and the third sleeve, the second gap located at the portion of the wellbore in contact with the first sleeve.
 20. The drill bit of claim 16, wherein the first sleeve, the second sleeve, and the third sleeve are spaced approximately one-hundred-twenty degrees from each other along the circumference of the bit body.
 21. The drill bit of claim 16, wherein: the second sleeve comprises a second geometrical axis, the second geometrical axis located parallel to the bit rotational axis; the second geometrical axis and the bit rotational axis are separated by a second distance; the third sleeve comprises a third geometrical axis, the third geometrical axis located parallel to the bit rotational axis; the third geometrical axis and the bit rotational axis are separated by a third distance; and the first distance, the second distance and the third distance are approximately each equal to each other.
 22. A downhole drilling tool operable to form a wellbore comprising: a bit body configured to remove material to form a portion of the wellbore; and a first eccentric sleeve coupled to the bit body at un uphole portion of the bit body.
 23. The downhole drilling tool of claim 22, wherein: the bit body is configured to rotate around a bit rotational axis; the first eccentric sleeve comprises a geometrical axis located parallel to the bit rotational axis; and the geometrical axis of the eccentric sleeve is offset from the bit rotational axis.
 24. The downhole drilling tool of claim 22, further comprising one or more second eccentric sleeves.
 25. The downhole drilling tool of claim 24, wherein: the bit body is configured to rotate around a bit rotational axis; each eccentric sleeve comprises a geometrical axis located parallel to the bit rotational axis; the geometrical axis of each eccentric sleeve is offset from the bit rotational axis.
 26. The downhole drilling tool of claim 22 wherein: the bit body is configured to rotate around a bit rotational axis; the first eccentric sleeve is configured to contact a portion of a wellbore formed by the downhole drilling tool; and the downhole drilling tool is configured to form a fulcrum point for directional drilling at the portion of the first sleeve contacting the wellbore at least once during a revolution of the bit body.
 27. The downhole drilling tool of claim 22 wherein the first eccentric sleeve is mass balanced around a bit rotational axis of the bit body.
 28. The downhole drilling tool of claim 22 wherein the first eccentric sleeve is configured to form a gap between the wellbore and the first sleeve at a second point approximately one-hundred-eighty degrees from the first point.
 29. A drilling tool, comprising: a bit body configured to rotate about a bit rotational axis; a first sleeve coupled to the bit body at an uphole portion of the bit body, the first sleeve: having a smaller diameter than the bit body; and having a portion aligned with a first edge portion of the bit body, the first edge portion located on the circumference of the bit body.
 30. The drilling tool of claim 29, wherein the first sleeve is configured to: form a fulcrum point for directional drilling at least once during a revolution of the bit body during formation of a wellbore; and contact a portion of the wellbore at a first point on the circumference of the first sleeve, and the fulcrum point is formed at the portion of the first sleeve contacting the wellbore.
 31. The drilling tool of claim 29, wherein the first sleeve is further configured to form a gap between the wellbore and a second point on the first sleeve, the second point located approximately one-hundred-eighty degrees from the first point.
 32. The drilling tool of claim 29, further comprising a second sleeve, the second sleeve: having a smaller diameter than the bit body; and having a portion aligned with a second edge portion of the bit body, the second edge portion located on the circumference of the bit body.
 33. The drilling tool of claim 32, further comprising a third sleeve, the second sleeve: having a smaller diameter than the bit body; and having a portion aligned with a third edge portion of the bit body, the third edge portion located on the circumference of the bit body.
 34. The drilling tool of claim 33, wherein: the first sleeve is configured to form a fulcrum point for directional drilling a wellbore at least once during a revolution of the bit body; the second sleeve is configured to form the fulcrum point for directional drilling at least once during a revolution of the bit body; and the third sleeve is configured to form the fulcrum point for directional drilling at least once during a revolution of the bit body.
 35. The drilling tool of claim 33, wherein the first sleeve, the second sleeve, and the third sleeve are spaced approximately one-hundred twenty degrees from each other along the circumference of the bit body. 